The composition of natural gas as it is recovered from natural deposits, i.e., at the wellhead, can vary considerably with respect to both organic and inorganic constituents. In addition to the principal constituent, methane, which commonly comprises about 90 volume percent, natural gas can contain ethane, propane, butane and higher hydrocarbons as well as nitrogen, carbon dioxide, hydrogen sulfide, and water. Those natural gas compositions containing condensable hydrocarbons such as propane, butane and pentane are referred to in the industry as wet gas, as distinguished from lean gas in which condensable hydrocarbons are not present, and dry gas in which the water content has been appreciably reduced. Sour gas contains H.sub.2 S and other sulfur compounds above specification limits. Mercury is present as an impurity in most natural gas streams and can be present in amounts as low as 0.02 .mu.g/Nm.sup.3 (micrograms per normal cubic meter) and as high as 300 .mu.g/Nm.sup.3. In the main the mercury impurity is in the form of elemental mercury, but in at least some instances mercury compounds, including organic mercury compounds, are also present. Although permissible levels of mercury impurity vary considerably depending upon the ultimate intended use of the purified product, a mercury concentration greater than about 0.01 .mu.g/Nm.sup.3 is considered undesirable, particularly in those instances in which the natural gas is to be liquefied by cryogenic processing.
In treating natural gas to achieve compliance with pipeline or use specifications, water is generally removed by absorption in hygroscopic liquids or adsorption on desiccants such as zeolitic molecular sieves. The acidic gases such as H.sub.2 S and CO.sub.2 can also be removed by adsorption on solid adsorbents or by means of regenerable chemical solvents which selectively react with these impurities to form complexes. The liquid hydrocarbon constituents of wet natural gas streams are usually recovered, at least in part, by pressure and/or temperature reduction to cause condensation of the less volatile species. The purification processes for removing mercury impurities are largely adsorption procedures, and in these perhaps the most common type of adsorbent is an activated carbon having supported thereon a mercury reactive material such as potassium iodide, sulfur, sulfuric acid, chlorine, silver, copper or various salts of silver or copper. Other supports for the mercury reactive materials include silicas, aluminas, silica-aluminas and zeolitic aluminosilicates. Ion-exchange resins, particularly the strongly basic anion-exchange types which have been reacted with a polysulfide, have also been reported as useful mercury adsorbents. See U.S. Pat. No. 4,591,490 (Horton) in this latter regard. The disclosure of U.S. Pat No. 4,500,327 (Nishino) and U.S. Pat. No. 4,196,173 (de Jong et al.) are pertinent to the use of activated carbon supports. The disclosure of U.S. Pat. No. 4,983,277 (Audeh et al.) and U.S. Pat. No. 4,986,898 Torihata et al.) relate to the use of alumina supports. The disclosure of U.S. Pat. No. 4,874,525 (Markovs) relates to the use of zeolite adsorbents for mercury removal.
It is also known that the effluent gas streams from many natural gas wells with relatively high flow rates contain entrained particles of mineral species derived from the sedimentary rock formations in which the natural gas deposits are formed. It is the usual practice to permit such particles to become disentrained by the force of gravity as the space velocity of the emerging gas stream is lowered by passage through a large expansion chamber located between the wellhead and the downstream treating facilities. In the case of wet gas streams, the solid mineral particles are conveniently accumulated in the slug catcher, designed to remove slugs of liquid hydrocarbons which condense out of the gas stream after it leaves the well, and periodically removed therefrom for disposal.